The invasion of contaminant solid particles (for example, in suspension) into a porous medium occurs in many technical applications: purification of liquids in the chemical industry, filtration of groundwater, injection of water to a reservoir in order to maintain the reservoir pressure, and drilling oil and gas producing wells. The determination of a change in the properties of a near-wellbore area, caused by invaded components of a flushing fluid (or another drilling fluid) during operations of well drilling, completion, or servicing is of a particular importance.
Drilling fluids are complex mixtures of polymers, particles (having a size from hundreds of micrometers to less than one micron), clays, and other additives contained in a “carrier” fluid being “a base” of the drilling fluid; water, oil, or a synthetic fluid can act as the carrier fluid.
In the process of drilling, the filtrate of drilling fluid as well as fine particles contained therein, polymers, and other components, which are subjected to an excessive pressure, penetrate into a near-wellbore area and significantly change the properties of the reservoir rock (primarily, reduce porosity and permeability). A complex structure of the near-wellbore area is developed that, as a rule, is divided into an external filter cake (formed on the wellbore wall and consisting of filtered solid particles), an invaded zone (internal filter cake), and a filtrate penetration zone.
During the wellbore cleaning process (by gradual putting into production), the external filter cake is partially broken while the penetrated components of the drilling fluid are partially washed out of the near-wellbore area, and its permeability and porosity are partially restored. Nevertheless, a portion of the components remains irreversibly held in the pore space of a rock (adsorption on the surfaces of pores, capture in steam restrictions, etc.), which results in an essential difference between the initial permeability and the permeability restored after carrying out the cleaning process.
The presence of a zone with deteriorated properties provides a significant loss of the reservoir energy and reduces the reservoir productivity relative to its natural condition, affects data of drillstem testers and logging tools, making them difficult to interpret.
Information on the distribution of the invaded particles of drilling fluid into the near-wellbore area allows the identification of the mechanism of reducing permeability and the determination of an area where such a reduction occurs.
Processes of capturing/mobilizing components of drilling fluids in the near-wellbore area, and associated changes in its properties are non-stationary and dynamic of nature and are described by a set of empirical parameters. Knowledge of these parameters is necessary for quantitative analysis, diagnosis and control of the properties of the near-wellbore area in oil and gas reservoirs.
However, the proven experimental methods for determining parameters characterizing the dynamics of the accumulation of solid components of process fluids within the pore space and associated changes in the rock permeability today is virtually absent.
The conventional laboratory technique for checking the quality of drilling fluid is a filtration experiment for its action on a core sample, followed by back pumping (i.e., displacement of the penetrated drilling fluid with an initial formation fluid), during which the dynamics of the permeability deterioration/restoration is measured as a function of the pore volume of a fluid (drilling fluid or reservoir fluid) pumped.
The conventional laboratory technique allows the measurement of only the integral permeability of the core sample, which change is due to the dynamics of growth/destruction of the external filter cake on the outer end of the core and due to the accumulation/removal of the components of the drilling fluid in the rock.
However, it is known (see, for example, Bedrikovetsky P., Marchesin D., Shecaira F., Souza A L, Milanez P V, Rezende E. Characterisation of deep bed filtration system from laboratory pressure drop measurements. Journal of Petroleum Science and Engineering. 2001. V. 32, Issues 2-4, pp. 167-177) that the data of the filtration experiment is not sufficient to determine the parameters characterizing the dynamics of the accumulation of filtered impurities in the pore space and the parameters of the internal filter cake (invaded zone). There is a need for additional information.
Furthermore, the distribution of solid components of a contaminant (for example, drilling fluid) in the core sample after treatment (pumping) or after back pumping is important information in understanding the damage formation mechanism and to select a respective technique for increasing a wellbore productivity index (to minimize a damage of the near-wellbore area).
Determination of this parameter also requires additional methods.
U.S. Pat. Nos. 5,253,719 and 5,027,379 disclose methods for determining a drilling fluid invasion using a core X-ray computer tomography with addition of a contrast agent to the base of drilling fluid (“carrier fluid”). However, the use of a contrast agent soluble in “the carrier fluid” does not make it possible to evaluate the depth of penetration of low-contrast additives contained in a drilling fluid because the depth of invasion of the drilling fluid and the majority of used additives are usually different.
Another method is disclosed in U.S. Pat. No. 4,722,095. It is based on a high X-ray attenuation coefficient of barite widely used as a weighting agent in drilling fluid. Firstly, a fluid filtrate is removed from a core sample, after which the pore and the total volumes of the core sample as well as the volume of barite particles that penetrated into the sample are measured using X-ray computer tomography.
Unfortunately, the use of barite as a contrast agent to evaluate the drilling fluid penetration depth is not always justified because the size of these particles is comparable with the size of pore throats and, consequently, most of them will be captured in small pores near the sample entrance site.
Other drilling fluid components (clay, polymers, water etc.) have a weak X-ray contrast and cannot be spatially differentiated with the required accuracy.
U.S. Pat. No. 7,099,811 proposes the use of the experimental apparatus with a long core holder (up to 40 cm) and multiple taps for measuring pressure to monitor the dynamics of damaged and restored permeability profiles along the core sample. The permeability profiles measured during filtration under laboratory conditions are a part of the input parameters for hydrodynamic simulation experiments where the distribution of permeability in the near-wellbore area is taken into account, using a cylindrical grid pattern forming very small blocks (a few millimeters) around the well.
However, this method makes practically impossible to separate the effect of the external filter cake from the effect of the invaded zone on the permeability of the near-end area of the core sample (the end exposed to the drilling or another fluid). Furthermore, a change in a pressure drop along the core sample is associated with the action of two mechanisms: a change in the relative phase permeability of the main phase (oil and gas) due to the presence of filtrate and a change in the absolute permeability due to blocking a portion of pores with the contaminant components. A contribution of separate mechanisms in a decrease (“damage”) of the permeability is important information, but individual effects of said mechanisms cannot always be separated from each other without additional measurements.
RF patent 2525093 discloses a method for predicting changes in the characteristics of the near-wellbore area (porosity, permeability, and saturation), caused by the action of drilling fluid, wherein the method involves a combination of mathematical modeling and laboratory filtration experiments on a core sample, wherein it is suggested to use a profile of the volume concentration of drilling fluid particles penetrated into the core sample to determine unambiguously parameters of the invaded zone and to obtain porosity and permeability profiles. The profile of the volume concentration of penetrated particles is proposed to obtain by using data of X-ray computed microtomography of the core sample, which is performed after the filtration experiment. However, this method is not applicable to low-contrast components. In addition, the accurate determination of the volume concentration profile of penetrated particles requires X-ray computed microtomography of the core sample with a resolution of at least 2 to 3 microns per voxel (voxel is the smallest element of three-dimensional image of a rectangular shape), which imposes a severe limitation on the maximum size of a scanned area and takes a lot of time for scanning and processing of data.
RU patent 2548930 describes a method for determining the distribution and a profile of a contaminant penetrated into porous medium, the method comprising coloring the solid components of the studied contaminant with a cationic dye, injecting the suspension of the colored contaminant through a porous medium sample, then splitting the porous medium sample, and analyzing the distribution and intensity of the cationic dye in the split. Fuchsine and/or methylene blue and/or brilliant green or other cationic dyes can be used as the dyes. It is possible to use cationic dyes having special properties, for example, fluorescent dyes. However, this method does not make it possible to obtain directly the distribution of the volume or mass concentration of penetrated colored component since for this purpose it is necessary to determine the quantitative relationship between these values and the color intensity of the cationic dye in the split.